Fracturing or gravel-packing fluid with CMHEC in brine

ABSTRACT

A method of treating a treatment zone of a subterranean formation penetrated by a wellbore of a well, the method including the steps of: (A) forming a treatment fluid comprising: (i) an aqueous phase comprising water having at least 1,000 ppm total dissolved inorganic salts; (ii) a carboxymethyl hydroxyethyl cellulose, wherein: (a) the carboxymethyl hydroxyethyl cellulose has a carboxymethyl degree of substitution is in the range of about 0.3 to about 0.45 per glucopyranose unit in the polymer; and (b) the carboxymethyl hydroxyethyl cellulose has a hydroxyethyl molecular substitution is in the range of about 2.1 to about 2.8 per glucopyranose unit in the polymer; and (iii) a breaker for the carboxymethyl hydroxyethyl cellulose; and (B) introducing the treatment fluid into the treatment zone. In embodiments, the carboxymethyl hydroxyethyl cellulose may or may not be crosslinked.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is a U.S. National Stage Application ofInternational Application No. PCT/US2013/054258 filed Aug. 9, 2013,which is incorporated herein by reference in its entirety for allpurposes.

TECHNICAL FIELD

This disclosure is in the field of producing crude oil or natural gasfrom subterranean formations. More specifically, the disclosuregenerally relates to fluids and methods of fracturing a treatment zoneof a subterranean formation penetrated by a wellbore of a well.

BACKGROUND

The demand for fresh water for oilfield operations has skyrocketed as aresult of the boom in hydraulic fracturing for shale plays. A typicalhydraulic fracturing treatment may consume, on average, three to fivemillion gallons of water (usually freshwater). This is particularlyproblematic offshore, where freshwater must be transported to the wellsite, whereas seawater is readily available, if it could be used toformulate a good fracturing fluid.

For additional reasons it is often desirable to form and use afracturing fluid having a high content of inorganic salt, whether onland or offshore. For example, salt curbs bacterial action. Saltprovides weight (that is, density) to a treatment fluid. Salt (e.g. KCl)usually reduces damage to production sands containing swellable clay.

Not many polymers perform well in brine, however, and even fewer performwell in hard brine such as seawater, which include a high concentrationof divalent metal ions such as magnesium and calcium.

GENERAL DESCRIPTION OF EMBODIMENTS

Carboxymethylhydroxyethyl cellulose (“CMHEC”) is a cellulose derivativehaving two different substituents bound onto some of the hydroxy groupsof the glucopyranose monomers that make up the cellulose backbone: oneis the carboxymethyl (“CM”) group, and the other is the hydroxyethyl(“HE”) group.

Use of CMHEC in fracturing fluids has offered many advantages overtraditional guar-based frac fluids. For example, CMHEC, as it comparesto a traditional guar-based fluid, provides superior cleanliness andreduced cost. Most commercially available guar has between 3% and 10% byweight insoluble residue, whereas CMHEC has less than 1% by weightinsoluble residue, that is, polymeric material that does not fullyhydrate. CMHEC provides improved cleanup and enhanced proppant pack,sand pack, or core regained permeability, which ultimately leads toenhanced oil or gas production from stimulation treatments. Anotherproperty that makes CMHEC a great candidate for use in treatments fluidsfor fracturing or frac-packing is that CMHEC has shown to providegreater proppant or gravel suspension as compared to guar-based fluidsor viscoelastic (VES) fluids.

In comparison to fracturing fluids that utilize carboxymethyl cellulose(“CMC”), which also offer the above advantages of cleanliness,CMHEC-based fluids offer enhanced performance and provide superior salttolerance. Thus, these fluids have potential for use with alternativesources of water.

CMHEC-based fluid systems can be used in brackish water, seawater, orbrine, even hard brine; however, the particular CMHEC should be selectedfor use in hard brine. These systems can be especially suitable foroffshore applications using seawater as well as those onshore involvinganything from pond to sewage to recycled flowback or produced waters,which often have dissolved salts. This disclosure can decrease thedemand of fresh water required for fracturing applications whileproviding a clean and reliable fracturing fluid.

The carboxy-substituted cellulose ethers, such as CMHEC and CMC, areusually commercially available as the alkali metal salt, usually thesodium salt. However, the metal is seldom referred to and they arecommonly referred to as CMC, CMHEC. Unless otherwise stated, it shouldbe understood that these are typically obtained as the alkali metalsalt. Of course, the carboxylate form (alkali metal salt) can be easilyconverted to the carboxylic acid form depending on the pH of an aqueousphase in which the polymeric material is dispersed or dissolved.

The molecular structure of carboxymethyl hydroxyethyl cellulose isrelated to its performance in a hydraulic fracturing fluid.Understanding the biopolymer at its molecular level not only helpsexplain the current rheological properties of a CMHEC fluid but alsoallow chemists to tailor the chemistry of the polymer to deliverspecific performances for specific applications.

It is believed that on which hydroxyl groups the CM or HE groups aresubstituted and how many of these substituents per glucopyranose monomerunit are critical to the polymer's physical and chemical properties andthe rheological properties of a CMHEC-based fluid.

The terms “DS” and “MS” are abbreviations for “degree of substitution”and “molar substitution,” respectively. Three hydroxyl groups are ineach anhydroglucose unit in the cellulose molecule. DS is the averagenumber of hydroxyl groups substituted in the cellulose peranhydroglucose unit. Thus, the DS of a cellulose derivative can be nohigher than 3. MS is the average number of moles of reactant combinedwith the cellulose per anhydroglucose unit. For the alkyl, carboxyalkyl,or acyl derivatives of cellulose, the DS and the MS are the same. Forthe hydroxyalkyl derivatives of cellulose, the MS is generally greaterthan the DS. The reason for this is that each time a hydroxyalkyl groupis reacted with the cellulose molecule, an additional hydroxyl group isformed which itself is capable of hydroxyalkylation. As a result ofthis, side chains of considerable length may form on the cellulosemolecule. The MS/DS ratio represents the average length of these sidechains. See, for example, Polymer Modification: Principles, Techniques,and Applications, edited by John J. Meister, CRC Press, 2000, pages49-52.

In general, the carboxymethyl DS of the CMHEC can be in a broad range ofabout 0.1 to about 1.0 and the hydroxyethyl MS can be in the range ofabout 0.1 to about 3. However, examples of hydration of several aqueousCMHEC-based fluid wherein the CMHEC has varying degrees of CM-DS andHE-MS substitutions leads to several critical conclusion about therelationship of the chemistry of the polymer at the molecular level andits performance as a fracturing fluid as well as its tolerance in anionic solution, especially a hard brine such as seawater: (A) CMHEC withcarboxymethyl degree of substitution (CM-DS) between about 0.3 to about0.45 per glucopyranose unit in polymer provides good salt tolerance evenin a hard brine such as seawater and also provides good cross-linkingefficiency; and (B) CMHEC with hydroxyethyl molecular substitution(HE-MS) between about 2.1 to about 2.8 per glucopyranose unit in polymerprovides good salt tolerance even in a hard brine such as seawater. Thepresence of hydroxyethyle groups along the side chains will help toimprove the hydration kinetics of CMHEC in water thus decrease thehydration time. The hydrophobicity of the hydroxylethyl groups will alsoimprove the thermal stability of gels and thus could be applied in wellswith higher BHST. In addition, it is believed that random CM-DS isbetter than block CM substitution. The CMHEC examples were obtained froma commercial supplier, which products are conventionally used for hairconditioner or in the food industry.

For example, the concentration of gel balls of the polymer that remainedunhydrated in seawater decreases as the HE-MS increases. Withoutnecessarily being limited by any theory, it is further believed thatwithin this HE-MS range, the higher the molecular substitution ofhydroxyethyl group, the more the polymer strand untangled, minimizingcrystalline segment and blockness in the polymer, leading to easierhydration and minimizing unhydrated gel balls.

The CMHEC-based fluid: is a clean, non-damaging, less expensivealternative to a guar-based fluid; has greater salt tolerance than other“clean” fluid systems (such as CMC-based fluids); and is robust,versatile, and has potential to work in a variety of water types.

A method of treating a treatment zone of a subterranean formationpenetrated by a wellbore of a well is provided, the method including:(A) forming a treatment fluid comprising: (i) an aqueous phasecomprising water having at least 1,000 ppm total dissolved inorganicsalts; (ii) a carboxymethyl hydroxyethyl cellulose, wherein: (a) thecarboxymethyl hydroxyethyl cellulose has a carboxymethyl degree ofsubstitution is in the range of about 0.3 to about 0.45 perglucopyranose unit in the polymer; and (b) the carboxymethylhydroxyethyl cellulose has a hydroxyethyl molecular substitution is inthe range of about 2.1 to about 2.8 per glucopyranose unit in thepolymer; and (iii) a breaker for the carboxymethyl hydroxyethylcellulose; and (B) introducing the treatment fluid into the treatmentzone.

In an embodiment, the treatment fluid is substantially free of anycrosslinker for the carboxymethyl hydroxyethyl cellulose. Such anembodiment of the CMHEC in a brine as a non-crosslinked fluid (sometimesreferred to as a “linear gel”) can be used, for example, as a pad fluidas part of a method of hydraulic fracturing in a treatment zone. As usedherein, “substantially free” means having less of any crosslinker thatwould be effective to increase the viscosity of the fluid by more than10% relative to an otherwise same CMHEC-based fluid that is completelynon-crosslinked. In such an embodiment, the treatment fluid ispreferably essentially free of any crosslinker for the carboxymethylhydroxyethyl cellulose. As used herein, “essentially free” means havingless of any crosslinker that would be effective to increase theviscosity of the fluid by more than 5% relative to an otherwise sameCMHEC-based fluid that is completely non-crosslinked. More preferably,in such an embodiment, the treatment fluid is completely free of anycrosslinker for the carboxymethyl hydroxyethyl cellulose. In such anembodiment, the aqueous phase preferably has an initial pH greater thanabout 5. More preferably, the aqueous phase has a pH in the range ofabout 5 to about 9. Most preferably, the aqueous phase has an initial pHin the rate of about 6 to about 8.

In another embodiment, the treatment fluid includes a crosslinker forthe carboxymethyl hydroxyethyl cellulose, wherein the crosslinkercomprises a polyvalent cation. As used herein, “polyvalent” means havinga valence state of 3 or greater. In such an embodiment, the polyvalentcation is preferably chelated. Preferably, the polyvalent cation isselected from the group consisting of aluminum, zirconium, titanium, andany combination thereof. In such an embodiment, the aqueous phasepreferably has an initial pH greater than about 5. More preferably, theaqueous phase has a pH in the range of about 5 to about 6.5. For acrosslinked fracturing fluid or gravel-packing fluid, it is desirablefor the treatment fluid to crosslink within a matter of minutes offorming the treatment fluid, for example, in less than about 10 minutes.

These and other embodiments of the disclosure will be apparent to oneskilled in the art upon reading the following detailed description.While the disclosure is susceptible to various modifications andalternative forms, specific embodiments thereof will be described indetail and shown by way of example. It should be understood, however,that it is not intended to limit the disclosure to the particular formsdisclosed.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODEDefinitions and Usages

General Interpretation

The words or terms used herein have their plain, ordinary meaning in thefield of this disclosure, except to the extent explicitly and clearlydefined in this disclosure or unless the specific context otherwiserequires a different meaning.

The words “comprising,” “containing,” “including,” “having,” and allgrammatical variations thereof are intended to have an open,non-limiting meaning. For example, a composition comprising a componentdoes not exclude it from having additional components, an apparatuscomprising a part does not exclude it from having additional parts, anda method having a step does not exclude it having additional steps. Whensuch terms are used, the compositions, apparatuses, and methods that“consist essentially of” or “consist of” the specified components,parts, and steps are specifically included and disclosed. As usedherein, the words “consisting essentially of,” and all grammaticalvariations thereof are intended to limit the scope of a claim to thespecified materials or steps and those that do not materially affect thebasic and novel characteristic(s) of the claimed invention.

The indefinite articles “a” or “an” mean one or more than one of thecomponent, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limitand an upper limit is disclosed, any number and any range falling withinthe range is also intended to be specifically disclosed. For example,every range of values (in the form “from a to b,” or “from about a toabout b,” or “from about a to b,” “from approximately a to b,” and anysimilar expressions, where “a” and “b” represent numerical values ofdegree or measurement) is to be understood to set forth every number andrange encompassed within the broader range of values.

Oil and Gas Reservoirs

In the context of production from a well, “oil” and “gas” are understoodto refer to crude oil and natural gas, respectively. Oil and gas arenaturally occurring hydrocarbons in certain subterranean formations.

A “subterranean formation” is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it.

A subterranean formation having a sufficient porosity and permeabilityto store and transmit fluids is sometimes referred to as a “reservoir.”

A subterranean formation containing oil or gas may be located under landor under the seabed off shore. Oil and gas reservoirs are typicallylocated in the range of a few hundred feet (shallow reservoirs) to a fewtens of thousands of feet (ultra-deep reservoirs or source rocks such asshale formation) below the surface of the land or seabed.

Well Servicing

To produce oil or gas from a reservoir, a wellbore is drilled into asubterranean formation, which may be the reservoir or adjacent to thereservoir.

Generally, well services include a wide variety of operations that maybe performed in oil, gas, geothermal, or water wells, such as drilling,cementing, completion, and intervention. Well services are designed tofacilitate or enhance the production of desirable fluids such as oil orgas from or through a subterranean formation. A well service usuallyinvolves introducing a fluid into a well.

Drilling, completion, and intervention operations can include varioustypes of treatments that are commonly performed on a well orsubterranean formation. During completion or intervention, stimulationis a type of treatment performed to enhance or restore the productivityof oil and gas from a well. Stimulation treatments fall into two maingroups: hydraulic fracturing and matrix treatments. Fracturingtreatments are performed above the fracture pressure of the subterraneanformation to create or extend a highly permeable flow path between theformation and the wellbore. Matrix treatments are performed below thefracture pressure of the formation. Other types of completion orintervention treatments can include, for example, gravel packing,consolidation, and controlling excessive water production.

Wells and Fluids

A “well” includes a wellhead and at least one wellbore from the wellheadpenetrating the earth. The “wellhead” is the surface termination of awellbore, which surface may be on land or on a seabed.

A “well site” is the geographical location of a wellhead of a well. Itmay include related facilities, such as a tank battery, separators,compressor stations, heating or other equipment, and fluid pits. Ifoffshore, a well site can include a platform.

The “wellbore” refers to the drilled hole, including any cased oruncased portions of the well or any other tubulars in the well. Awellbore can have portions that are vertical, horizontal, or anything inbetween, and it can have portions that are straight, curved, orbranched. As used herein, “uphole,” “downhole,” and similar terms arerelative to the direction of the wellhead, regardless of whether awellbore portion is vertical or horizontal.

A wellbore can be used as a production or injection wellbore. Aproduction wellbore is used to produce hydrocarbons from the reservoir.An injection wellbore is used to inject a fluid, for example, liquidwater or steam, to drive oil or gas to a production wellbore.

As used herein, introducing “into a well” means introducing at leastinto and through the wellhead. According to various techniques known inthe art, tubulars, equipment, tools, or fluids can be directed from thewellhead into any desired portion of the wellbore.

As used herein, the word “tubular” means any kind of structural body inthe general form of a tube. Examples of tubulars in oil wells include,but are not limited to, a drill pipe, a casing, a tubing string, a coiltubing, a line pipe, and a transportation pipe.

As used herein, unless the context otherwise requires, a treatment fluidrefers to the specific properties and composition of a fluid at the timethe fluid is being introduced into a well. In addition, it should beunderstood that, during the course of a well operation such as drilling,cementing, completion, or intervention, or during a specific treatment,the specific properties and composition of a type of fluid can be variedor several different types of fluids can be used.

For example, the compositions can be varied to adjust viscosity orelasticity of the fluids to accommodate changes in the concentrations ofparticulate to be carried downhole. It can also be desirable toaccommodate expected changes in temperatures encountered by the fluidsduring the course of the treatment. By way of another example, it can bedesirable to accommodate the longer duration that an earlier-introducedtreatment fluid may need to maintain viscosity before breaking comparedto the shorter duration that a later-introduced treatment fluid may needto maintain viscosity before breaking. Changes in concentration of aparticulate, viscosity-increasing agent, breaker, or other additives inthe various treatment fluids of a treatment operation can be made instepped changes of concentrations or ramped changes of concentrations.

As used herein, the word “treatment” refers to any treatment forchanging a condition of a portion of a wellbore or a subterraneanformation adjacent a wellbore; however, the word “treatment” does notnecessarily imply any particular treatment purpose. A treatment usuallyinvolves introducing a fluid for the treatment, in which case it may bereferred to as a treatment fluid, into a well. As used herein, a“treatment fluid” is a fluid used in a treatment. The word “treatment”in the term “treatment fluid” does not necessarily imply any particulartreatment or action by the fluid.

In the context of a well or wellbore, a “portion” or “interval” refersto any downhole portion or interval along the length of a wellbore.

A “zone” refers to an interval of rock along a wellbore that isdifferentiated from uphole and downhole zones based on hydrocarboncontent or other features, such as permeability, composition,perforations, or other fluid communication with the wellbore, faults, orfractures. A zone of a wellbore that penetrates a hydrocarbon-bearingzone that is capable of producing hydrocarbon is referred to as a“production zone.” A “treatment zone” refers to an interval of rockalong a wellbore into which a fluid is directed to flow from thewellbore. As used herein, “into a treatment zone” means into and throughthe wellhead and, additionally, through the wellbore and into thetreatment zone.

A “design” refers to the estimate or measure of one or more parametersplanned or expected for a particular fluid or stage of a well service ortreatment. For example, a fluid can be designed to have components thatprovide a minimum density or viscosity for at least a specified timeunder expected downhole conditions. A well service may include designparameters such as fluid volume to be pumped, required pumping time fora treatment, or the shear conditions of the pumping.

The term “design temperature” refers to an estimate or measurement ofthe actual temperature at the downhole environment during the time of atreatment. For example, the design temperature for a well treatmenttakes into account not only the bottom hole static temperature (“BHST”),but also the effect of the temperature of the fluid on the BHST duringtreatment. The design temperature for a fluid is sometimes referred toas the bottom hole circulation temperature (“BHCT”). Because fluids maybe considerably cooler than BHST, the difference between the twotemperatures can be quite large. Ultimately, if left undisturbed asubterranean formation will return to the BHST.

Particles and Particulates

As used herein, a “particle” refers to a body having a finite mass andsufficient cohesion such that it can be considered as an entity buthaving relatively small dimensions. A particle can be of any sizeranging from molecular scale to macroscopic, depending on context.

As used herein, particulate or particulate material refers to matter inthe physical form of distinct particles in a solid or liquid state(which means such an association of a few atoms or molecules). As usedherein, a particulate is a grouping of particles having similar chemicalcomposition and particle size ranges anywhere in the range of about 0.5micrometer (500 nm), for example, microscopic clay particles, to about 3millimeters, for example, large grains of sand.

A particulate can be of solid or liquid particles. As used herein,however, unless the context otherwise requires, particulate refers to asolid particulate.

It should be understood that the terms “particle” and “particulate,”includes all known shapes of particles including substantially rounded,spherical, oblong, ellipsoid, rod-like, fiber, polyhedral (such as cubicmaterials), etc., and mixtures thereof. For example, the term“particulate” as used herein is intended to include solid particleshaving the physical shape of platelets, shavings, flakes, ribbons, rods,strips, spheroids, toroids, pellets, tablets or any other physicalshape.

As used herein, a fiber is a particle or grouping of particles having anaspect ratio L/D greater than 5/1.

A particulate will have a particle size distribution (“PSD”). As usedherein, “the size” of a particulate can be determined by methods knownto persons skilled in the art.

One way to measure the approximate particle size distribution of a solidparticulate is with graded screens. A solid particulate material willpass through some specific mesh (that is, have a maximum size; largerpieces will not fit through this mesh) but will be retained by somespecific tighter mesh (that is, a minimum size; pieces smaller than thiswill pass through the mesh). This type of description establishes arange of particle sizes. A “+” before the mesh size indicates theparticles are retained by the sieve, while a “−” before the mesh sizeindicates the particles pass through the sieve. For example, −70/+140means that 90% or more of the particles will have mesh sizes between thetwo values.

Particulate materials are sometimes described by a single mesh size, forexample, 100 U.S. Standard mesh. If not otherwise stated, a reference toa single particle size means about the mid-point of theindustry-accepted mesh size range for the particulate.

Dispersions and Solutions

A dispersion is a system in which particles of a substance of onechemical composition and physical state are dispersed in anothersubstance of a different chemical composition or physical state. Inaddition, phases can be nested. If a substance has more than one phase,the most external phase is referred to as the continuous phase of thesubstance as a whole, regardless of the number of different internalphases or nested phases.

A dispersion can be classified in different ways, including, forexample, based on the size of the dispersed particles, the uniformity orlack of uniformity of the dispersion, and, if a fluid, by whether or notprecipitation occurs.

A dispersion is considered to be heterogeneous if the dispersedparticles are not dissolved and are greater than about 1 nanometer insize. (For reference, the diameter of a molecule of toluene is about 1nm and a molecule of water is about 0.3 nm).

Heterogeneous dispersions can have gas, liquid, or solid as an externalphase. For example, in a case where the dispersed-phase particles areliquid in an external phase that is another liquid, this kind ofheterogeneous dispersion is more particularly referred to as anemulsion. A solid dispersed phase in a continuous liquid phase isreferred to as a sol, suspension, or slurry, partly depending on thesize of the dispersed solid particulate.

A dispersion is considered to be homogeneous if the dispersed particlesare dissolved in solution or the particles are less than about 1nanometer in size. Even if not dissolved, a dispersion is considered tobe homogeneous if the dispersed particles are less than about 1nanometer in size.

A solution is a special type of homogeneous mixture. A solution isconsidered homogeneous: (a) because the ratio of solute to solvent isthe same throughout the solution; and (b) because solute will neversettle out of solution, even under powerful centrifugation, which is dueto intermolecular attraction between the solvent and the solute. Anaqueous solution, for example, saltwater, is a homogenous solution inwhich water is the solvent and salt is the solute.

Hydratability or Solubility

As referred to herein, “hydratable” means capable of being hydrated bycontacting the hydratable material with water. Regarding a hydratablematerial that includes a polymer, this means, among other things, toassociate sites on the polymer with water molecules and to unravel andextend the polymer chain in the water.

The term “solution” is intended to include not only true molecularsolutions but also dispersions of a polymer wherein the polymer is sohighly hydrated as to cause the dispersion to be visually clear andhaving essentially no particulate matter visible to the unaided eye. Theterm “soluble” is intended to have a meaning consistent with thesemeanings of solution.

A substance is considered to be “soluble” in a liquid if at least 10grams of the substance can be hydrated or dissolved in one liter of theliquid when tested at 77° F. and 1 atmosphere pressure for 2 hours,considered to be “insoluble” if less than 1 gram per liter, andconsidered to be “sparingly soluble” for intermediate solubility values.

As will be appreciated by a person of skill in the art, thehydratability, dispersibility, or solubility of a substance in water canbe dependent on the salinity, pH, or other substances in the water.Accordingly, the salinity, pH, and additive selection of the water canbe modified to facilitate the hydratability, dispersibility, orsolubility of a substance in aqueous solution. To the extent notspecified, the hydratability, dispersibility, or solubility of asubstance in water is determined in deionized water, at neutral pH, andwithout any other additives.

As used herein, “salt tolerance” of a polymeric material means ithydrates well in the presence of dissolved salts to provide viscosity,for example, in 2% KCl or in presence of divalent ions, for example, insynthetic seawater.

The “source” of a chemical species in a solution or in a fluidcomposition can be a material or substance that is itself the chemicalspecies, or that makes the chemical species chemically availableimmediately, or it can be a material or substance that gradually orlater releases the chemical species to become chemically available inthe solution or the fluid.

Fluids

A fluid can be a homogeneous or heterogeneous. In general, a fluid is anamorphous substance that is or has a continuous phase of particles thatare smaller than about 1 micrometer that tends to flow and to conform tothe outline of its container.

Every fluid inherently has at least a continuous phase. A fluid can havemore than one phase. The continuous phase of a treatment fluid is aliquid under Standard Laboratory Conditions.

The term “water” is used generally herein to include fresh water orbrine, unless the context otherwise requires.

As used herein, the term “brine” is intended to include, unless thecontext otherwise requires, any aqueous solution having greater than1,000 ppm total dissolved inorganic salts. Oil field brines commonlycontain varying concentrations of inorganic salts, e.g., sodiumchloride, calcium chloride, and magnesium salts. Aqueous solutions arefrequently modified by addition of potassium chloride to stabilize thesubsurface clay. Accordingly, potassium chloride is frequentlyencountered in brines.

As used herein, the term “hard brine” is intended to include, unless thecontext otherwise requires, any aqueous solution having greater than1,000 ppm total dissolved divalent inorganic salts, such as magnesium orcalcium. For example, a hard brine can have about 1,000 ppm to about16,000 ppm divalent cations such calcium ions.

As used herein, a “water-based” fluid means that water or an aqueoussolution is the dominant material of the continuous phase, that is,greater than 50% by weight, of the continuous phase of the fluid basedon the combined weight of water and any other solvents in the phase(that is, excluding the weight of any dissolved solids).

In contrast, an “oil-based” fluid means that oil is the dominantmaterial by weight of the continuous phase of the fluid. In thiscontext, the oil of an oil-based fluid can be any oil.

Gels and Deformation

Technically, a “gel” is a semi-solid, jelly-like physical state or phasethat can have properties ranging from soft and weak to hard and tough.Shearing stresses below a certain finite value fail to produce permanentdeformation. The minimum shear stress which will produce permanentdeformation is referred to as the shear strength or gel strength of thegel.

The physical state of a gel is formed by a network of interconnectedmolecules, such as a crosslinked polymer or a network of micelles in acontinuous liquid phase. The network gives a gel phase its structure andan apparent yield point. At the molecular level, a gel is a dispersionin which both the network of molecules is continuous and the liquid iscontinuous. A gel is sometimes considered as a single phase.

A hydrogel is a gel state having a network of polymer chains that arehydrophilic and for which water is the dispersion medium. In some cases,a “hydrogel” refers to a natural or synthetic polymeric material that isa highly absorbent and that can form such a gel.

In the oil and gas industry, however, the term “gel” may be used torefer to any fluid having a viscosity-increasing agent, regardless ofwhether it is a viscous fluid or meets the technical definition for thephysical state of a gel. A “base gel” is a term used in the field for afluid that includes a viscosity-increasing agent, such as guar or otherpolymer, but that excludes crosslinking agents. Typically, a base gel ismixed with another fluid containing a crosslinker, wherein the mixtureis adapted to form a crosslinked gel. Similarly, a “crosslinked gel” mayrefer to a substance having a viscosity-increasing agent that iscrosslinked, regardless of whether it is a viscous fluid or meets thetechnical definition for the physical state of a gel.

As used herein, a substance referred to as a “gel” is subsumed by theconcept of “fluid” if it is a pumpable fluid.

Viscosity Measurements (For Example, for Hydraulic Fracturing or GravelPacking)

There are numerous ways of measuring and modeling viscous properties,and new developments continue to be made. The methods depend on the typeof fluid for which viscosity is being measured. A typical method forquality assurance or quality control (QA/QC) purposes uses a couettedevice, such as a FANN™ Model 35 or Model 50 viscometer or a CHANDLER™Model 5550 HPHT viscometer. Such a viscometer measures viscosity as afunction of time, temperature, and shear rate. The viscosity-measuringinstrument can be calibrated using standard viscosity silicone oils orother standard viscosity fluids.

A substance is considered to be a fluid if it has an apparent viscosityless than 5,000 mPa·s (cP) (independent of any gel characteristic). Forreference, the viscosity of pure water is about 1 mPa·s (cP).

As used herein, for the purposes of hydraulic fracturing a fluid isconsidered to be “viscous” if it has an apparent viscosity of 200 mPa·s(cP) at 40 s⁻¹ shear rate or higher. The viscosity of a viscous fluid isconsidered to break or be broken if the viscosity is greatly reduced.Preferably, although not necessarily for all applications depending onhow high the initial viscosity of the fluid, the viscous fluid breaks toa viscosity of less than 50% of the viscosity of the maximum viscosityor less than 200 mPa·s (cP) at 40 s⁻¹ shear rate.

General Measurement Terms

Unless otherwise specified or unless the context otherwise clearlyrequires, any ratio or percentage means by weight.

Unless otherwise specified or unless the context otherwise clearlyrequires, the phrase “by weight of the water” means the weight of thewater of an aqueous phase of the fluid without the weight of anyviscosity-increasing agent, dissolved salt, suspended particulate, orother materials or additives that may be present in the water.

If there is any difference between U.S. or Imperial units, U.S. unitsare intended. For example, “GPT” or “gal/Mgal” means U.S. gallons perthousand U.S. gallons and “ppt” means pounds per thousand U.S. gallons.

The barrel (“bbl”) is the unit of measure used in the US oil industry,wherein one barrel equals 42 U.S. gallons. Standards bodies such as theAmerican Petroleum Institute (API) have adopted the convention that ifoil is measured in oil barrels, it will be at 14.696 psi and 60° F.,whereas if it is measured in cubic meters, it will be at 101.325 kPa and15° C. (or in some cases 20° C.). The pressures are the same but thetemperatures are different—60° F. is 15.56° C., 15° C. is 59° F., and20° C. is 68° F. However, if all that is needed is to convert a volumein barrels to a volume in cubic meters without compensating fortemperature differences, then 1 bbl equals 0.159 m³ or 42 U.S. gallons.

Unless otherwise specified, mesh sizes are in U.S. Standard Mesh.

The micrometer (μm) may sometimes be referred to herein as a micron.

The conversion between pound per gallon (lb/gal or ppg) and kilogram percubic meter (kg/m³) is: 1 lb/gal=(0.4536 kg/lb)×(gal/0.003785 m³)=120kg/m³.

The conversion between pound per thousand gallons (lb/Mgal) and kilogramper cubic meter (kg/m³) is: 1 lb/Mgal=(0.4536 kg/lb)×(Mgal/3.785m³)=0.12 kg/m³.

The conversion between pound per barrel (lb/bbl) and kilogram per cubicmeter (kg/m³) is: 1 lb/bbl=(0.4536 kg/lb)×(bbl/0.159 m³)=2.85 kg/m³.

Hydraulic Fracturing

The purpose of a hydraulic fracturing treatment is to provide animproved flow path for oil or gas to flow from a hydrocarbon-bearingformation to the wellbore. In addition, a fracturing treatment canfacilitate the flow of injected treatment fluids from the well into theformation. A treatment fluid adapted for this purpose is sometimesreferred to as a fracturing fluid. The fracturing fluid is pumped at asufficiently high flow rate and pressure into the wellbore and into thesubterranean formation to create or enhance one or more fractures in thesubterranean formation. Creating a fracture means making a new fracturein the formation. Enhancing a fracture means enlarging a pre-existingfracture in the formation.

A frac pump is used for hydraulic fracturing. A frac pump is ahigh-pressure, high-volume pump. The fracturing fluid may be pumped downinto the wellbore at high rates and pressures, for example, at a flowrate in excess of 50 barrels per minute (2,100 U.S. gallons per minute)at a pressure in excess of 5,000 pounds per square inch (“psi”). Thepump rate and pressure of the fracturing fluid may be even higher, forexample, flow rates in excess of 100 barrels per minute and pressures inexcess of 10,000 psi are often encountered.

Fracturing a subterranean formation often uses hundreds of thousands ofgallons of fracturing fluid or more. Further, it is often desirable tofracture more than one treatment zone of a well. Therefore, a highvolume of fracturing fluids is often used in fracturing of a well, whichmeans that a low-cost fracturing fluid is desirable. Because of theready availability and relative low cost of water compared to otherliquids, among other considerations, a fracturing fluid is usuallywater-based.

The creation or extension of a fracture in hydraulic fracturing mayinitially occur suddenly. When this happens, the fracturing fluidsuddenly has a fluid flow path through the fracture to flow more rapidlyaway from the wellbore. As soon as the fracture is created or enhanced,the sudden increase in the flow of fluid away from the well reduces thepressure in the well. Thus, the creation or enhancement of a fracture inthe formation may be indicated by a sudden drop in fluid pressure, whichcan be observed at the wellhead. After initially breaking down theformation, the fracture may then propagate more slowly, at the samepressure or with little pressure increase. It can also be detected withseismic techniques.

A newly-created or newly-extended fracture will tend to close togetherafter the pumping of the fracturing fluid is stopped. To prevent thefracture from closing, a material is usually placed in the fracture tokeep the fracture propped open and to provide higher fluid conductivitythan the matrix of the formation. A material used for this purpose isreferred to as a proppant.

A proppant is in the form of a solid particulate, which can be suspendedin the fracturing fluid, carried downhole, and deposited in the fractureto form a proppant pack. The proppant pack props the fracture in an opencondition while allowing fluid flow through the permeability of thepack. The proppant pack in the fracture provides a higher-permeabilityflow path for the oil or gas to reach the wellbore compared to thepermeability of the matrix of the surrounding subterranean formation.This higher-permeability flow path increases oil and gas production fromthe subterranean formation.

A particulate for use as a proppant is usually selected based on thecharacteristics of size range, crush strength, and solid stability inthe types of fluids that are encountered or used in wells. Preferably, aproppant should not melt, dissolve, or otherwise degrade from the solidstate under the downhole conditions.

The proppant is selected to be an appropriate size to prop open thefracture and bridge the fracture width expected to be created by thefracturing conditions and the fracturing fluid. If the proppant is toolarge, it will not easily pass into a fracture and will screenout tooearly. If the proppant is too small, it will not provide the fluidconductivity to enhance production. See, for example, W. J. McGuire andV. J. Sikora, “The Effect of Vertical Fractures on Well Productivity,”Trans., AIME (1960) 219, 401-403. In the case of fracturing relativelypermeable or even tight-gas reservoirs, a proppant pack should providehigher permeability than the matrix of the formation. In the case offracturing ultra-low permeable formations, such as shale formations, aproppant pack should provide for higher permeability than the naturallyoccurring fractures or other micro-fractures of the fracture complexity.

Appropriate sizes of particulate for use as a proppant are typically inthe range from about 8 to about 100 U.S. Standard Mesh. A typicalproppant is sand-sized, which geologically is defined as having alargest dimension ranging from about 0.06 millimeters up to about 2millimeters (mm) (The next smaller particle size class below sand sizeis silt, which is defined as having a largest dimension ranging fromless than about 0.06 mm down to about 0.004 mm.) As used herein,proppant does not mean or refer to suspended solids, silt, fines, orother types of insoluble solid particulate smaller than about 0.06 mm(about 230 U.S. Standard Mesh). Further, it does not mean or refer toparticulates larger than about 3 mm (about 7 U.S. Standard Mesh).

The proppant is sufficiently strong, that is, has a sufficientcompressive or crush resistance, to prop the fracture open without beingdeformed or crushed by the closure stress of the fracture in thesubterranean formation. For example, for a proppant material thatcrushes under closure stress, a 20/40 mesh proppant preferably has anAPI crush strength of at least 4,000 psi closure stress based on 10%crush fines according to procedure API RP-56. A 12/20 mesh proppantmaterial preferably has an API crush strength of at least 4,000 psiclosure stress based on 16% crush fines according to procedure APIRP-56. This performance is that of a medium crush-strength proppant,whereas a very high crush-strength proppant would have a crush-strengthof about 10,000 psi. In comparison, for example, a 100-mesh proppantmaterial for use in an ultra-low permeable formation such as shalepreferably has an API crush strength of at least 5,000 psi closurestress based on 6% crush fines. The higher the closing pressure of theformation of the fracturing application, the higher the strength ofproppant is needed. The closure stress depends on a number of factorsknown in the art, including the depth of the formation.

Further, a suitable proppant should be stable over time and not dissolvein fluids commonly encountered in a well environment. Preferably, aproppant material is selected that will not dissolve in water or crudeoil.

Suitable proppant materials include, but are not limited to, silicasand, ground nut shells, ground fruit pits, sintered bauxite, glass,plastics, ceramic materials, processed wood, composite materials, resincoated particulates, and any combination of the foregoing. Mixtures ofdifferent kinds or sizes of proppant can be used as well.

In conventional reservoirs, a proppant commonly has a median sizeanywhere within the range of about 20 to about 100 U.S. Standard Mesh.For a synthetic proppant, it commonly has a median size anywhere withinthe range of about 8 to about 100 U.S. Standard Mesh.

The concentration of proppant in the treatment fluid depends on thenature of the subterranean formation. As the nature of subterraneanformations differs widely, the concentration of proppant in thetreatment fluid may be in the range of from about 0.03 kilograms toabout 12 kilograms of proppant per liter of liquid phase (from about 0.1lb/gal to about 25 lb/gal).

A resinous material can be coated on the proppant. Purposes of thecoating can include improving the strength of a proppant, changing awettability characteristic of the proppant for improving flow of oil orgas, or reducing the migration of a particulate in the formation that issmaller than the proppant, which can plug pores in the formation orproppant pack, decrease production, or cause abrasive damage to wellborepumps, tubing, and other equipment.

The term “coated” does not imply any particular degree of coverage onthe proppant particulates, which coverage can be partial or complete.

As used herein, the term “resinous material” means a material that is aviscous liquid and has a sticky or tacky characteristic when testedunder Standard Laboratory Conditions. A resinous material can include aresin, a tackifying agent, and any combination thereof in anyproportion. The resin can be or include a curable resin.

For example, some or all of the proppant can be coated with a curableresin. The curable resin can be allowed to cure on the proppant prior tothe proppant being introduced into the well. The cured resin coating onthe proppant provides a protective shell encapsulating the proppant andkeeping the fine particulates in place if the proppant was crushed orprovides a different wettable surface than the proppant without thecoating.

A curable resin coating on the proppant can be allowed to cure after theproppant is placed in the subterranean formation for the purpose ofconsolidating the proppant of a proppant pack to form a “proppantmatrix.” As used herein, “proppant matrix” means a closely associatedgroup of proppant particles as a coherent mass of proppant. Typically, acured resin consolidates the proppant pack into a hardened, permeable,coherent mass. After curing, the resin reinforces the strength of theproppant pack and reduces the flow back of proppant from the proppantpack relative to a similar proppant pack without such a cured resincoating.

A resin or curable resin can be selected from natural resins, syntheticresins, and any combination thereof in any proportion. Natural resinsinclude, but are not limited to, shellac. Synthetic resins include, butare not limited to, epoxies, furans, phenolics, and furfuryl alcohols,and any combination thereof in any proportion. An example of a suitablecommercially available resin is the EXPEDITE™ product sold byHalliburton Energy Services, Inc. of Duncan, Okla.

By way of another example, some or all of the proppant can be coatedwith a tackifying agent, instead of, or in addition to, a curable resin.The tackifying agent acts to consolidate and help hold together theproppant of a proppant pack to form a proppant matrix. Such a proppantmatrix can be flexible rather than hard. The tackifying-agent-coatedproppant in the subterranean formation tends to cause smallparticulates, such as fines, to stick to the outside of the proppant.This helps prevent the fines from flowing with a fluid, which couldpotentially clog the openings to pores.

Tackifying agents include, but are not limited to, polyamides,polyesters, polyethers and polycarbamates, polycarbonates, and anycombination thereof in any proportion. An example of a suitablecommercially available tackifying agent is the SANDWEDGE™ product soldby Halliburton Energy Services, Inc. of Duncan, Okla.

Sand Control and Gravel Packing

Gravel packing is commonly used as a sand-control method to preventproduction of formation sand or other fines from a poorly consolidatedsubterranean formation. In this context, “fines” are tiny particles,typically having a diameter of 43 microns or smaller, that have atendency to flow through the formation with the production ofhydrocarbon. The fines have a tendency to plug small pore spaces in theformation and block the flow of oil. As all the hydrocarbon is flowingfrom a relatively large region around the wellbore toward a relativelysmall area around the wellbore, the fines have a tendency to becomedensely packed and screen out or plug the area immediately around thewellbore. Moreover, the fines are highly abrasive and can be damaging topumping and oilfield other equipment and operations.

Placing a relatively larger particulate near the wellbore helps filterout the sand or fine particles and prevents them from flowing into thewell with the produced fluids. The primary objective is to stabilize theformation while causing minimal impairment to well productivity.

The particulate used for this purpose is referred to as “gravel.” In theoil and gas field, and as used herein, the term “gravel” is refers torelatively large particles in the sand size classification, that is,particles ranging in diameter from about 0.1 mm up to about 2 mm.Generally, a particulate having the properties, including chemicalstability, of a low-strength proppant is used in gravel packing. Anexample of a commonly used gravel packing material is sand having anappropriate particulate size range.

In one common type of gravel packing, a mechanical screen is placed inthe wellbore and the surrounding annulus is packed with a particulate ofa larger specific size designed to prevent the passage of formation sandor other fines. The screen holds back gravel during flow back.

In some gravel packing applications, a resinous material can be coatedon the particulate. The term “coated” does not imply any particulardegree of coverage on the particulates, which coverage can be partial orcomplete.

Frac-Packing

The combination of a hydraulically-induced fracture with a gravel-packcompletion has been termed a “frac-pac.” The primary purpose of afrac-pac completion is to help eliminate the high skins often associatedwith cased-hole gravel packs by providing a highly conductive flow paththrough the near-wellbore formation damaged zone.

Carrier Fluid for Particulate

A fluid can be adapted to be a carrier fluid for a particulate.

For example, a proppant used in fracturing or a gravel used in gravelpacking may have a much different density than the carrier fluid. Forexample, sand has a specific gravity of about 2.7, whereas water has aspecific gravity of 1.0 at Standard Laboratory Conditions of temperatureand pressure. A proppant or gravel having a different density than waterwill tend to separate from water very rapidly.

Increasing Viscosity of Fluid for Suspending Particulate

Increasing the viscosity of a fluid can help prevent a particulatehaving a different specific gravity than a surrounding phase of thefluid from quickly separating out of the fluid.

A viscosity-increasing agent can be used to increase the ability of afluid to suspend and carry a particulate material in a fluid. Aviscosity-increasing agent can be used for other purposes, such asmatrix diversion, conformance control, or friction reduction.

A viscosity-increasing agent is sometimes referred to in the art as aviscosifying agent, viscosifier, thickener, gelling agent, or suspendingagent. In general, any of these refers to an agent that includes atleast the characteristic of increasing the viscosity of a fluid in whichit is dispersed or dissolved. There are several kinds ofviscosity-increasing agents or techniques for increasing the viscosityof a fluid.

In general, because of the high volume of fracturing fluid typicallyused in a fracturing operation, it is desirable to efficiently increasethe viscosity of fracturing fluids to the desired viscosity using aslittle viscosity-increasing agent as possible. In addition, relativelyinexpensive materials are preferred. Being able to use only a smallconcentration of the viscosity-increasing agent requires a lesserconcentration of the viscosity-increasing agent in order to achieve thedesired fluid viscosity.

Polymers for Increasing Viscosity

Certain kinds of polymers can be used to increase the viscosity of afluid. In general, the purpose of using a polymer is to increase theability of the fluid to suspend and carry a particulate material.Polymers for increasing the viscosity of a fluid are preferably solublein the external phase of a fluid. Polymers for increasing the viscosityof a fluid can be naturally occurring polymers such as polysaccharides,derivatives of naturally occurring polymers, or synthetic polymers.

Water-Soluble Polymers for Increasing Viscosity

Treatment fluids used in high volumes, such as fracturing fluids, areusually water-based. Efficient and inexpensive viscosity-increasingagents for water include certain classes of water-soluble polymers.

The water-soluble polymer can have an average molecular weight in therange of from about 50,000 Da to 20,000,000 Da, most preferably fromabout 100,000 Da to about 4,000,000 Da.

The viscosity-increasing agent can be provided in any form that issuitable for the particular treatment fluid or application. For example,the viscosity-increasing agent can be provided as a liquid, gel,suspension, or solid additive that is incorporated into a treatmentfluid.

The viscosity-increasing agent should be present in a treatment fluid ina form and in an amount at least sufficient to impart the desiredviscosity to a treatment fluid. A viscosity-increasing agent may bepresent in the fluids in a concentration in the range of from about0.01% to about 5% by weight of the continuous phase therein.

Problem with Certain Hydratable Materials and Dissolved Ions

The commonly used water-soluble viscosity-increasing agents,water-soluble friction-reducing agents, and water-solubleelasticity-increasing agents are hydratable. As referred to herein,“hydratable” means capable of being hydrated by contacting thehydratable material with water. Regarding a hydratable material thatincludes a polymer, this means, among other things, to associate siteson the polymer with water molecules and to unravel and extend thepolymer chain in the water. It is desirable for viscosity-increasingagents to be able to be hydrated directly in the water at theconcentration to be used for the fluid.

A common problem with using hydratable materials is that many of thecommonly-used hydratable materials used for such purposes are sensitiveto dissolved ions in the water. The hydratable materials are oftenespecially sensitive to divalent cations such as calcium and magnesium.For example, divalent cations such as calcium and magnesium can inhibitand slow the time required for hydration of certain types of polymerscommonly used for such purposes.

Therefore, fracturing fluids often require the use of water that doesnot contain high concentrations of total dissolved solids, especiallyhigh concentrations of dissolved divalent cations. For this reason, mostfracturing fluids require a minimum quality of water. Most fracturingfluids are run in potable or freshwater. However, potable water andfreshwater is becoming increasingly expensive and difficult to come by,especially considering the high volumes of water required forfracturing.

To solve the problem of hydration in water having high concentrations ofTDS, especially due to high concentration of divalent cations, anotherconventional approach has included chemically modifying the hydratablepolymer so that it is better capable of hydrating in water having highTDS. Other approaches to handling water having high concentrations ofTDS were by chemical addition to reduce the effect of salt. Anotherconventional approach has included heating a brine to about 140° F. (60°C.) to increase the hydration rate of the hydratable polymer in thebrine. However, heating of brine is time consuming, expensive, anddifficult to achieve in the field. Further, heating of a brine may causethe viscosity-increasing agent to build excessive viscosity if latersubjected to high wellbore temperatures. It can be prohibitivelyexpensive to heat large quantities of water.

Yet another attempted solution has been to treat the water to removesome of the interfering ions. There are several existing methods oftreating non-freshwater such as evaporative distillation and reverseosmosis. Both of these treatment methods remove the vast majority of TDSfrom the water. Removing excess ions by distillation or reverse osmosisis an expensive process. Of course, the costs of treating water aremultiplied by the large volumes of water required for well treatments,especially for the volumes of water required for water-fracturingtreatments.

Water Classifications

Total dissolved solids (“TDS”) refers to the sum of all minerals,metals, cations, and anions dissolved in water. As most of the dissolvedsolids are typically salts, the amount of salt in water is oftendescribed by the concentration of total dissolved solids in the water.

Freshwater is water containing low concentrations (typically <1%) ofdissolved salts and other total dissolved solids.

Broadly speaking, “brine” is often understood to be water containing anysubstantial concentration of dissolved inorganic salts, regardless ofthe particular concentration. Therefore, “brine” may broadly refer towater containing anywhere from about 1,000 ppm to high percentages ofdissolved salts. Brines used for oil field purposes sometimes containtotal dissolved solids of up to about 10% or higher.

More technically, however, the terms “brackish water,” “saline water,”“seawater,” “brine,” and other terms regarding water may sometimes beused to refer to more precise ranges of concentrations of TDS.

Although the specific ranges of TDS for various types of water are notuniversally agreed upon, as used herein, the terms for classifying waterbased on concentration of TDS will generally be understood as defined inTable 1.

TABLE 1 Classification of Water Based on TDS Concentration andRelationship to Density TDS Concentration Ranges Density @ 20° C. Waterppm lb/gal (US) g/ml lb/gal (US) Potable <250 <0.0021 Freshwater <1,000<0.0083 <0.998 <8.33 Brackish  1,000-15,000 0.0083-0.0417 Saline15,000-30,000 0.0417-0.1251 Seawater 30,000-40,000 0.1251-0.33381.020-1.029 8.51-8.59 Brine >40,000 >0.3338

Hardness is a more specific measure of the dissolved calcium (Ca⁺²),magnesium (Mg⁺²), and ferrous (Fe⁺², a form of iron) ions in water.

Water can be classified based on its source. Classifying water based onits source is independent of the classification based on a particularparameter, such as TDS.

Due to a number of factors, the range of TDS concentrations innaturally-occurring surface water, such as freshwater, brackish water,saline water, and seawater, can vary considerably within the definedranges for the type of water. Water that is not naturally occurring canbe similarly classified by the concentration of TDS, of course, which isgenerally with reference to the concentrations of TDS in the varioustypes of naturally-occurring water.

Non-potable water that may be suitable for treatment fluids that includea hydratable polymer that is not sensitive to certain dissolved ionsincludes freshwater, brackish water, saline water, and seawater. Ofcourse, if locally available, brackish water or seawater is relativelycheap.

The average composition of seawater, as reported by Karl K. Turekian,Oceans, 1968, Prentice-Hall, is shown in Table 3.

TABLE 3 Typical Composition of Seawater Concentration Dissolved Ionmg/kg (ppm) Chloride (Cl⁻) 19,345 Sodium (Na⁺) 10,752 Sulfate (SO₄ ²⁻)2701 Magnesium (Mg²⁺) 1295 Calcium (Ca²⁺) 416 Potassium (K⁺) 390Bicarbonate (HCO₃ ²⁻) 145 Bromide (Br⁻) 66 Borate (BO₃ ²⁻) 27 Strontium(Sr²⁺) 13 Fluoride (F⁻) 1

A synthetic seawater (ASTM.D1141) has the following composition: 19359mg/ml chloride; 2702 mg/ml sulfate; 142 mg/ml bicarbonate; 11155 mg/mlsodium+potassium; 1297 mg/ml magnesium; 408 mg/ml calcium; TDS=35169mg/l; pH=8.2.

It is desirable to be able to use CMHEC in a treatment fluid forfracturing or gravel packing operations with a brine. In variousembodiments of the disclosed method, the aqueous phase has at least1,000 ppm of dissolved divalent cations. The aqueous phase can have atleast 25,000 ppm total dissolved inorganic salts. In variousembodiments, the aqueous phase has less than 100,000 ppm total dissolvedinorganic salts, and more preferably, less than 50,000 ppm totaldissolved inorganic salts. Most preferably, the aqueous phase comprisesseawater. In some embodiments, the aqueous phase comprises seawaterwithout diluting the aqueous phase with any other source of water.

Selection of Carboxymethyl Hydroxyethyl Cellulose (CMHEC)

Examples of hydration of several aqueous CMHEC-based fluid wherein theCMHEC has varying degrees of CM-DS and HE-MS substitutions leads toseveral critical conclusion about the relationship of the chemistry ofthe polymer at the molecular level and its performance as a fracturingfluid as well as its salt tolerance in an ionic solution, especially ahard brine such as seawater: (A) CMHEC with carboxymethyl degree ofsubstitution (CM-DS) between about 0.3 to about 0.45 per glucopyranoseunit in polymer provides good salt tolerance even in a hard brine suchas seawater and also provides good cross-linking efficiency; and (B)CMHEC with hydroxyethyl molecular substitution (HE-MS) between about 2.1to about 2.8 per glucopyranose unit in polymer provides good salttolerance even in a hard brine such as seawater. In addition, it isbelieved that random CM-DS is better than block CM substitution. TheCMHEC examples were obtained from a commercial supplier, which productsare conventionally used for hair conditioner or in the food industry.

In various preferred embodiments, the treatment fluid includes a CMHECwith a with CM-DS in the range of about 0.3 to about 0.45 and HE-MS inthe range of about 2.8 to about 2.9.

Crosslinking of Polymer to Increase Viscosity of a Fluid or Form a Gel

The viscosity of a fluid at a given concentration ofviscosity-increasing agent can be greatly increased by crosslinking theviscosity-increasing agent. A crosslinking agent, sometimes referred toas a crosslinker, can be used for this purpose. A crosslinker interactswith at least two polymer molecules to form a “crosslink” between them.

If crosslinked to a sufficient extent, the polysaccharide may form a gelwith water. Gel formation is based on a number of factors including theparticular polymer and concentration thereof, the particular crosslinkerand concentration thereof, the degree of crosslinking, temperature, anda variety of other factors known to those of ordinary skill in the art.

The degree of crosslinking depends on the type of viscosity-increasingpolymer used, the type of crosslinker, concentrations, temperature ofthe fluid, etc. Shear is usually required to mix the base gel and thecrosslinking agent. Therefore, the actual number of crosslinks that arepossible and that actually form also depends on the shear level of thesystem. The number of crosslinks is believed to significantly alterfluid viscosity.

For a polymeric viscosity-increasing agent, any crosslinking agent thatis suitable for crosslinking the chosen monomers or polymers may beused.

Cross-linking agents typically comprise at least one metal ion that iscapable of cross-linking the viscosity-increasing agent molecules.

Some crosslinking agents form substantially permanent crosslinks withviscosity-increasing polymer molecules. Such crosslinking agentsinclude, for example, crosslinking agents of at least one metal ion thatis capable of crosslinking gelling agent polymer molecules. Examples ofsuch crosslinking agents include, but are not limited to, zirconiumcompounds (such as, for example, zirconium lactate, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium maleate, zirconium citrate, zirconium oxychloride, andzirconium diisopropylamine lactate); titanium compounds (such as, forexample, titanium lactate, titanium maleate, titanium citrate, titaniumammonium lactate, titanium triethanolamine, and titaniumacetylacetonate); aluminum compounds (such as, for example, aluminumacetate, aluminum lactate, or aluminum citrate); antimony compounds;chromium compounds; iron compounds (such as, for example, ironchloride); copper compounds; zinc compounds; sodium aluminate; or acombination thereof.

Preferably, the source of a polyvalent metal cation is derived from awater-soluble salt of the polyvalent metal in which the metal is in thesame cationic valence state as the crosslinking species. By this, it isintended to mean that the metal ion which forms the crosslinking neednot be freshly formed as by a change in the valence state of the metalion.

Where present, the cross-linking agent generally should be included inthe fluids in an amount sufficient, among other things, to provide thedesired degree of cross linking. In some embodiments, the cross-linkingagent may be present in the treatment fluids in an amount in the rangeof from about 0.01% to about 5% by weight of the treatment fluid.

Buffering compounds may be used if desired, for example, to delay orcontrol the cross linking reaction. These may include glycolic acid,carbonates, bicarbonates, acetates, phosphates, and any other suitablebuffering agent.

Sometimes, however, crosslinking is undesirable, as it may cause thepolymeric material to be more difficult to break and it may leave anundesirable residue in the formation.

Breaking Viscosity of a Fluid

After a treatment fluid is placed where desired in the well and for thedesired time, the downhole fluid usually must then be removed from thewellbore or the formation.

For example, in the case of hydraulic fracturing, the fluid should beremoved leaving the proppant in the fracture and without damaging theconductivity of the proppant bed. To accomplish this removal, theviscosity of the treatment fluid must be reduced to a very lowviscosity, preferably near the viscosity of water, for optimal removalfrom the propped fracture. Similarly, when a viscosified fluid is usedfor gravel packing, the viscosified fluid must be removed from thegravel pack.

Reducing the viscosity of a viscosified treatment fluid is referred toas “breaking” the fluid. Chemicals used to reduce the viscosity oftreatment fluids are called breakers.

Breakers for reducing viscosity must be selected to meet the needs ofeach situation. First, it is important to understand the generalperformance criteria for breaking. In reducing the viscosity of thetreatment fluid to a near water-thin state, the breaker must maintain acritical balance. Premature reduction of viscosity during the pumping ofa treatment fluid can jeopardize the treatment. Inadequate reduction offluid viscosity after pumping can also reduce production if the requiredconductivity is not obtained. A breaker should be selected based on itsperformance in the temperature, pH, time, and desired viscosity profilefor each specific treatment.

In fracturing, for example, the ideal viscosity versus time profilewould be if a fluid maintained 100% viscosity until the fracture closedon proppant and then immediately broke to a thin fluid. Some breakinginherently occurs during the 0.5 to 4 hours required to pump mostfracturing treatments. One guideline for selecting an acceptable breakerdesign is that at least 50% of the fluid viscosity should be maintainedat the end of the pumping time. This guideline may be adjusted accordingto job time, desired fracture length, and required fluid viscosity atreservoir temperature.

A typical gravel pack break criteria is a minimum 4-hour break time,however, it is still desirable for a gravel-packing fluid to breakwithin a few days.

No particular mechanism is necessarily implied by breaking or breakerregarding the viscosity of a fluid.

For example, for use a fluid viscosified with a polymeric material asthe viscosity-increasing agent, a breaker can operate by cleaving thebackbone of polymer by hydrolysis of acetyl group, cleavage ofglycosidic bonds, oxidative/reductive cleavage, free radical breakage,or a combination of these processes. Accordingly, such a breaker canreduce the molecular weight of the polymer by cutting the long polymerchain. As the length of the polymer chain is cut, the viscosity of thefluid is reduced.

In another example, a breaker may reverse a crosslinking of aviscosity-increasing agent or attack the crosslinker.

Chemical Breakers

Chemical breakers used to help clean up a filtercake or break theviscosity of a viscosified fluid are generally grouped into severalclasses: oxidizers, enzymes, chelating agents, and acids.

Oxidizers commonly used to reduce viscosity of natural polymersincludes, for example, sodium persulfate, potassium persulfate, ammoniumpersulfate, lithium or sodium hypochlorites, chlorites, peroxide sources(sodium perborate, sodium percarbonate, calcium percarbonate,urea-hydrogen peroxide, hydrogen peroxide, etc.), bromates, periodates,permanganates, etc. In these types of breakers, oxidation reductionchemical reactions occur as the polymer chain is broken.

Different oxidizers are selected based on their performance at differenttemperature and pH ranges. Consideration is also given to the rate ofoxidation at a particular temperature and pH range.

Enzymes are also used to break the natural polymers in oil fieldapplications. They are generally used at low temperature 25° C. (77° F.)to 70° C. (158° F.) as at higher temperature they denature and becomeineffective. At very low temperatures, enzymes are not as effective asthe rate of breakage of polymer is very slow and they are generally notrecommended. Different types of enzymes are used to break differenttypes of bond in the polysaccharides. Some enzymes break onlyα-glycosidic linkage and some break β-glycosidic linkage inpolysaccharides. Some enzymes break polymers by hydrolysis and some byoxidative pathways. A specific enzyme is needed to break a specificpolymer/polysaccharide. Enzymes are referred to as Nature's catalystsbecause most biological processes involve an enzyme. Enzymes are largeprotein molecules, and proteins consist of a chain of building blockscalled amino acids. The simplest enzymes may contain fewer than 150amino acids while typical enzymes have 400 to 500 amino acids.

Acids also provide a break via hydrolysis. Acids, however, pose variousdifficulties for practical applications. Acids are not used as apolysaccharide polymer breaker very often because of cost, poor breakrate control, chemical compatibility difficulties, and corrosion ofmetal goods.

A breaker may be included in a treatment fluid in a form andconcentration at selected to achieve the desired viscosity reduction ata desired time.

The breaker may be formulated to provide a delayed break, if desired.For example, a suitable breaker may be encapsulated if desired. Suitableencapsulation methods are known to those skilled in the art. Onesuitable encapsulation method involves coating the selected breaker in aporous material that allows for release of the breaker at a controlledrate. Another suitable encapsulation method that may be used involvescoating the chosen breakers with a material that will degrade whendownhole so as to release the breaker when desired. Resins that may besuitable include, but are not limited to, polymeric materials that willdegrade when downhole.

A treatment fluid can optionally include an activator or a retarder to,among other things, optimize the break rate provided by a breaker.Examples of such activators include, but are not limited to, acidgenerating materials, chelated iron, copper, cobalt, and reducingsugars. Examples of retarders include sodium thiosulfate, methanol, anddiethylenetriamine.

Delayed breakers, activators, and retarders can be used to help controlthe breaking of a fluid, but these may add additional complexity andcost to the design of a treatment fluid.

pH and pH Adjuster or Buffer

Preferably, the initial pH of the aqueous phase of the treatment fluidis in the range of about 5 to about 9, and more preferably in the rangeof about 7 to 8.5. In an embodiment including a crosslinker for theCMHEC, however, the initial pH of the aqueous phase of the treatmentfluid is preferably in the range of about 5 to about 6.5.

In certain embodiments, the treatment fluids can include a pH-adjuster.Preferably, the pH adjuster does not have undesirable properties.

The pH-adjuster may be present in the treatment fluids in an amountsufficient to maintain or adjust the pH of the fluid. In someembodiments, the pH-adjuster may be present in an amount sufficient tomaintain or adjust the pH of the fluid to a pH in the desired range.

In general, a pH-adjuster may function, among other things, to affectthe hydrolysis rate of the viscosity-increasing agent. In someembodiments, a pH-adjuster may be included in the treatment fluid, amongother things, to adjust the pH of the treatment fluid to, or maintainthe pH of the treatment fluid near, a pH that balances the duration ofcertain properties of the treatment fluid (for example the ability tosuspend particulate) with the ability of the breaker to reduce theviscosity of the treatment fluid or a pH that will result in a decreasein the viscosity of the treatment fluid such that it does not hinderproduction of hydrocarbons from the formation.

The pH-adjuster may be any other substance known in the art capable ofmaintaining the pH in a limited range. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriatepH-adjuster and amount thereof to use for a chosen application.

Optional Encapsulation of Solid Agents for Delayed Release

Any solid agent can be encapsulated to delay the release of the solidagent. Encapsulation techniques can be used in embodiments forcontrolling the delayed release of a breaker, for example.

Solid agents can be encapsulated by any suitable technique includingspray coating a variety of coating materials thereon. Such coatingmaterials include, but are not limited to, waxes, drying oils such astung oil and linseed oil, polyurethanes and cross-linked partiallyhydrolyzed polyacrylics. Degradable polymers such as polyesters, polylactic acid, and the like may also be used if desired. A solid agentalso may be encapsulated in the form of an aqueous solution containedwithin a particulate porous solid material that remains dry and freeflowing after absorbing an aqueous solution and through which theaqueous solution slowly diffuses. Examples of such particulate poroussolid materials include, but are not limited to, diatomaceous earth,zeolites, silica, alumina, metal salts of alumino-silicates, clays,hydrotalcite, styrene-divinylbenzene based materials, cross-linkedpolyalkylacrylate esters, and cross-linked modified starches. In orderto provide additional delay to the release of the solid agentencapsulated in a particulate porous solid material described above, anexternal coating of a polymeric material through which an aqueoussolution slowly diffuses can be placed on the porous solid material.Examples of such polymeric materials include, but are not limited to,EDPM rubber, polyvinyldichloride (PVDC), nylon, waxes, polyurethanes andcross linked partially hydrolyzed acrylics.

Other Fluid Additives

A treatment fluid can contain additives that are commonly used in oilfield applications, as known to those skilled in the art. These include,but are not necessarily limited to, inorganic water-soluble salts, saltsubstitutes (such as trimethyl or tetramethyl ammonium chloride),surfactants, defoamers, breaker aids, oxygen scavengers, alcohols, scaleinhibitors, corrosion inhibitors, hydrate inhibitors, fluid-loss controladditives, oxidizers, chelating agents, water-control agents (such asrelative permeability modifiers), consolidating agents, proppantflowback control agents, conductivity enhancing agents, claystabilizers, sulfide scavengers, fibers, nanoparticles, bactericides,and combinations thereof.

Of course, additives should be selected for not interfering with thepurpose of the fluid.

Method of Treating a Well with the Treatment Fluid

A method of treating a well, is provided, the method including: forminga treatment fluid according to the disclosure; and introducing thetreatment fluid into the well.

Designing a Fracturing Treatment for a Treatment Zone

Fracturing methods can include a step of designing or determining afracturing treatment for a treatment zone of the subterranean formationprior to performing the fracturing stage. For example, a step ofdesigning can include: (a) determining the design temperature and designpressure; (b) determining the total designed pumping volume of the oneor more fracturing fluids to be pumped into the treatment zone at a rateand pressure above the fracture pressure of the treatment zone; (c)designing a fracturing fluid, including its composition and rheologicalcharacteristics; (d) designing the pH of the continuous phase of thefracturing fluid, if water-based; (e) determining the size of a proppantof a proppant pack previously formed or to be formed in fractures in thetreatment zone; and (f) designing the loading of any proppant in thefracturing fluid.

Designing a Gravel Packing Treatment

Gravel packing methods can include a step of designing or determining agravel packing treatment for a treatment zone of the subterraneanformation. According to an embodiment, the step of designing caninclude: (a) determining the design temperature and design pressure; (b)determining the total designed pumping volume of the one or moretreatment fluids to be pumped into the treatment zone; (c) determiningthe pumping time and rate; (d) designing the treatment fluid, includingits composition and rheological characteristics; (e) designing the pH ofthe continuous phase of the treatment fluid, if water-based; (f)determining the size of a gravel; and (g) designing the loading of thegravel in the fluid.

Forming Treatment Fluid

A treatment fluid can be prepared at the job site, prepared at a plantor facility prior to use, or certain components of the fluid can bepre-mixed prior to use and then transported to the job site. Certaincomponents of the fluid may be provided as a “dry mix” to be combinedwith fluid or other components prior to or during introducing the fluidinto the well.

In certain embodiments, the preparation of a treatment fluid can be doneat the job site in a method characterized as being performed “on thefly.” The term “on-the-fly” is used herein to include methods ofcombining two or more components wherein a flowing stream of one elementis continuously introduced into flowing stream of another component sothat the streams are combined and mixed while continuing to flow as asingle stream as part of the on-going treatment. Such mixing can also bedescribed as “real-time” mixing.

Introducing the Treatment Fluid into the Treatment Zone

Often the step of delivering a fluid into a well is within a relativelyshort period after forming the fluid, for example, less within 30minutes to one hour. More preferably, the step of delivering the fluidis immediately after the step of forming the fluid, which is “on thefly.”

It should be understood that the step of delivering a fluid into a wellcan advantageously include the use of one or more fluid pumps.

Introducing Below or Above Fracture Pressure

In an embodiment, the step of introducing is at a rate and pressurebelow the fracture pressure of the treatment zone. This can be useful,for example, in a gravel-packing step.

In an embodiment, the step of introducing comprises introducing underconditions for fracturing a treatment zone. The fluid is introduced intothe treatment zone at a rate and pressure that are at least sufficientto fracture the zone.

Performing a Fracturing Stage

In general, a fracturing treatment preferably includes pumping the oneor more fracturing fluids into a treatment zone at a rate and pressureabove the fracture pressure of the treatment zone.

Monitoring for Fracturing

Any of the fracturing methods can include a step of monitoring to helpdetermine the end of a fracturing stage. The end of a fracturing stageis the end of pumping into a treatment zone, which can be due toscreenout at or near the wellbore or other mechanical or chemicaldiversion of fluid to a different treatment zone.

One technique for monitoring is measuring the pressure in the wellborealong the treatment zone. Another technique includes a step ofdetermining microseismic activity near the zone to confirm an increasein fracture complexity in the treatment zone.

Gravel Packing

In an embodiment, the step of introducing comprises introducing underconditions for gravel packing the treatment zone.

The combination of a hydraulically-induced fracture with a gravel-packcompletion has been termed a “frac-pac.” The primary purpose of afrac-pac completion is to help eliminate the high skins often associatedwith cased-hole gravel packs by providing a highly conductive flow paththrough the near-wellbore formation damaged zone.

Allowing Time for Breaking in the Well

After the step of introducing the treatment fluid, in an embodiment themethod includes the step of allowing time for breaking the viscosity ofthe fluid in the well. This can be accomplished, for example, byshutting in the treatment zone before flowing back fluid from the well.The breaking of the viscosity of the treatment fluid preferably occurswith time under the conditions in the zone of the subterranean fluid.

In various embodiments, the treatment fluid is adapted to break at thedesign temperature within about 5 days. More preferably, the treatmentfluid is adapted to break within 24 hours. Most preferably, thetreatment fluid is adapted to break in less than 4 hours at the designtemperature for the treatment.

Flow Back Conditions

In various embodiments, a step of flowing back from the treatment zoneis within about 5 days of the step of introducing. In anotherembodiment, the step of flowing back is within about 24 hours of thestep of introducing. In some embodiments, the step of flowing back iswithin about 4 hours of the step of introducing.

Producing Hydrocarbon from Subterranean Formation

Preferably, after any such use of a fluid according to the disclosure, astep of producing hydrocarbon from the well or a particular zone is thedesirable objective.

CONCLUSION

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein.

The exemplary fluids disclosed herein may directly or indirectly affectone or more components or pieces of equipment associated with thepreparation, delivery, recapture, recycling, reuse, or disposal of thedisclosed fluids. For example, the disclosed fluids may directly orindirectly affect one or more mixers, related mixing equipment, mudpits, storage facilities or units, fluid separators, heat exchangers,sensors, gauges, pumps, compressors, and the like used generate, store,monitor, regulate, or recondition the exemplary fluids. The disclosedfluids may also directly or indirectly affect any transport or deliveryequipment used to convey the fluids to a well site or downhole such as,for example, any transport vessels, conduits, pipelines, trucks,tubulars, or pipes used to fluidically move the fluids from one locationto another, any pumps, compressors, or motors (for example, topside ordownhole) used to drive the fluids into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the fluids, and anysensors (i.e., pressure and temperature), gauges, or combinationsthereof, and the like. The disclosed fluids may also directly orindirectly affect the various downhole equipment and tools that may comeinto contact with the chemicals/fluids such as, but not limited to,drill string, coiled tubing, drill pipe, drill collars, mud motors,downhole motors or pumps, floats, MWD/LWD tools and related telemetryequipment, drill bits (including roller cone, PDC, natural diamond, holeopeners, reamers, and coring bits), sensors or distributed sensors,downhole heat exchangers, valves and corresponding actuation devices,tool seals, packers and other wellbore isolation devices or components,and the like.

The particular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. It is, therefore, evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope of thepresent disclosure.

The various elements or steps according to the disclosed elements orsteps can be combined advantageously or practiced together in variouscombinations or sub-combinations of elements or sequences of steps toincrease the efficiency and benefits that can be obtained from thedisclosure.

It will be appreciated that one or more of the above embodiments may becombined with one or more of the other embodiments, unless explicitlystated otherwise.

This illustrative disclosure can be practiced in the absence of anyelement or step that is not specifically disclosed or claimed.

Furthermore, no limitations are intended to the details of composition,design, or steps herein shown, other than as described in the claims.

What is claimed is:
 1. A method of treating a treatment zone of asubterranean formation penetrated by a wellbore of a well, the methodcomprising: (A) forming a treatment fluid comprising: (i) an aqueousphase comprising water having at least 1,000 ppm total dissolvedinorganic salts; (ii) a carboxymethyl hydroxyethyl cellulose, wherein:(a) the carboxymethyl hydroxyethyl cellulose has a carboxymethyl degreeof substitution is in the range of about 0.3 to about 0.45 perglucopyranose unit in the polymer; and (b) the carboxymethylhydroxyethyl cellulose has a hydroxyethyl molecular substitution is inthe range of about 2.1 to about 2.8 per glucopyranose unit in thepolymer; (iii) a crosslinker for the carboxymethyl hydroxyethylcellulose, wherein the crosslinker comprises a polyvalent cation; and(iv) a breaker for the carboxymethyl hydroxyethyl cellulose; wherein theaqueous phase has or is adjusted to have an initial pH in the range of4.5-6.5; and (B) introducing the treatment fluid into the treatmentzone.
 2. The method according to claim 1, wherein the aqueous phase hasat least 1,000 ppm of dissolved divalent cations.
 3. The methodaccording to claim 2, wherein the aqueous phase has at least 25,000 ppmtotal dissolved inorganic salts.
 4. The method according to claim 1,wherein the treatment fluid is water-based.
 5. The method according toclaim 1, wherein the breaker is selected from the group consisting of anoxidizer, an enzyme, or an acid.
 6. The method according to claim 5,wherein the breaker comprises a delayed release breaker.
 7. The methodaccording to claim 5, wherein the breaker is encapsulated.
 8. The methodaccording to claim 1, wherein the treatment fluid is aged less than 24hours prior to introducing into the treatment zone.
 9. The methodaccording to claim 1, wherein the treatment fluid additionally comprisesa particulate selected from the group consisting of: proppant andgravel.
 10. The method according to claim 1, wherein the well is aproduction well.